Hydraulic fracturing is commonly used in stimulation of tight gas reservoirs. In mid nineties, most of the tight gas reservoirs were fractured utilizing the crosslinked gelled fluids. In an effort to reduce treatment costs, slick water fracturing has emerged as the method of choice. The success of slick water fracturing has been attributed to its ability to contact a larger surface area of the reservoir with minimum fluid-induced damage to the fracture face and within the proppant pack. In a typical treatment, several million gallons of water is pumped at an average rate of 65 bpm with sand ranging in concentration from 0.25 to 1.0 ppg. Several chemicals are added on the fly during the treatment. The common additives include scale inhibitor, friction reducers, biocides, clay swelling inhibitors, oxygen scavengers and surfactants.
One of the continuing challenges in slick water fracturing of tight gas reservoirs is the post treatment fluid recovery. About 60 to 90% of the injected fluids stay in the reservoirs. It is likely that large quantities of water are trapped in the area surrounding the fracture and within the fracture itself. This could be due to interfacial tension between water and reservoir rock or capillary end effect in and around the vicinity of the face of the fractured rock. The trapped fluid has detrimental effect on well productivity. Several approaches have been used to overcome this problem. Low vapor pressure co-solvents can be added to the fluid or as a post fluid to increase the evaporation of the water in the dry gas. Surfactants are also incorporated in the fracturing fluid to reduce the capillary pressure between the fluid and the gas.
Surfactants work by lowering the surface tension of the gas-liquid or liquid-solid interface. A few surfactants, such as a 8:1 weight ratio solution of water:decyl-dimethyl amine oxide change the wettability of the rock from water wet to mixed wettability; which further lowers capillary pressure. However, surfactants alone do not provide adequate water recovery.
In parallel, microemulsions may be used to aid the flowback of fracturing fluid from wells. The concept is to add a water-wetting conventional surfactant to an emulsion containing a solvent; thereby to get the advantages of both in terms of helping reduce capillary pressure. Prior art solution in U.S. Pat. No. 5,310,002 discloses such attempt with an additive for addition to conventional well treatment fluids to enhance the ability of the fluids to be recovered from subterranean formations, to generate a foam in association with the fluids and/or to enhance the ability of the fluids to remove water and other connate fluids interlocked with gas in the formations. The additive includes about 25% to about 50% by volume of a microemulsion generating component which forms an acid and/or water external microemulsion when added to the treatment fluid, and about 50% to about 75% by volume of a foaming agent component. The foaming agent component includes at least one nonionic surface active agent having an HLB of from 12 to 22. The additive is particularly suitable for addition to foam fracturing fluids useful for stimulating tight or otherwise unconventional gas formations.